1. Field of the Invention
This invention relates to transmission of information along a tubular string, and more particularly to a system for acoustically transmitting signals across a connection in the tubular string.
2. Description of the Related Art
The oilfield industry currently uses two extremes of communication within wellbores. The classification of these two extremes relates to the timing of the wellbore construction, typically during the wellbore construction and after construction during the operation of the wellbore for production of hydrocarbons.
During the drilling and completion phases, communication is accomplished using a form of mud pulse telemetry commonly utilized within measurement while drilling (MWD) systems. Alternative methods of telemetry, such as low frequency electromagnetic and acoustics, have been investigated and found to be of limited or specialized use. In general MWD telemetry is bound by the speed of sound and the viscous properties in the drilling fluid, thus data rates for mud pulse telemetry seldom exceed 10 bits per second.
An increase in the number and complexity of downhole sensors in MWD systems has increased the need for higher data rates for the telemetry link. Also, introduction of rotary closed loop steering systems has increased the need for bi-directional telemetry from the top to the bottom of the well.
Industry efforts to develop high data rate telemetry have included methods to incorporate fiber optic or wire technology into the drillstring, transmitting acoustic signals through the drill string, and transmitting electromagnetic signals through the earth surrounding the drill string. U.S. Pat. No. 4,095,865 to Denison, et al., describes sections of drill pipe, pre-wired with an electrical conductor. However, each section of pipe is specially fabricated and difficult and expensive to maintain. Acoustic systems suffer from attenuation and filtering effects caused by reflections at each drill joint connection. Attempts have been made to predict the filtering effects, for example see U.S. Pat. No. 5,477,505 to Drumheller. In most such techniques, signal boosters or repeaters are required on the order of every 1000 feet. To date, the only practical and commercial method of MWD telemetry is modulation of mud flow and pressure with it's relatively slow data rate.
Once a well is drilled and completed, special sensors and control devices are commonly installed to assist in operation of the well. These devices historically have been individually controlled or monitored by dedicated lines. These controls were initially hydraulically operated valves (e.g. subsurface safety valves) or were sliding sleeves operated by shifting tools physically run in on a special wireline to shift the sleeve, as needed.
The next evolution in downhole sensing and control was moving from hydraulic to electric cabling permanently mounted in the wellbore and communicating back to surface control and reporting units. Initially, these control lines provided both power and data/command between downhole and the surface. With advances in sensor technology, the ability to multiplex along wires now allows multiple sensors to be used along a single wire path. The industry has begun to use fiber optic transmission lines in place of traditional electric wire for data communication.
A common element of these well operation sensors and devices is the sending of power and information along the installed telemetry path. The telemetry path is typically installed in long lengths across multiple sections of jointed tubular. Thus, the installation of the telemetry path is required after major tubulars are installed in the well. The devices along the telemetry path must comply with a common interface and power specification. Any malfunction in the line puts the power transmission and communication in jeopardy.
Thus, there is a demonstrated need for higher data rate telemetry systems with bi-directional transmission capability for use with jointed tubulars.